In the production of crude oil, it is frequently found that the crude oil is sufficiently viscous to require the injection of steam into the petroleum reservoir. Ideally, the petroleum reservoir would be completely homogeneous and the steam would enter all portions of the reservoir evenly. However, it is often found that this does not occur. Instead, steam selectively enters a small portion of the reservoir while effectively bypassing other portions of the reservoir. Eventually, "steam breakthrough" occurs and most of the steam flows directly from an injection well to a production well, bypassing a large part of the petroleum reservoir.
It is possible to overcome this problem with various remedial measures, e.g., by plugging off certain portions of the injection well. For example, see U.S. Pat. Nos. 4,470,462 and 4,501,329, assigned to the assignee of the present invention. However, to institute these remedial measures, it is necessary to determine which portions of the reservoir are selectively receiving the injected steam. This is often a difficult problem.
Various methods have been proposed for determining how injected steam is being distributed in the wellbore. Bookout ("Injection Profiles During Steam Injection", API Paper No. 801-43C, May 3, 1967) summarizes some of the known methods for determining steam injection profiles and is incorporated herein by reference for all purposes.
The liquid and vapor phase distributions within a steam injection wellbore are important in the evaluation of steamflood performance. They can indicate which parts of the reservoir have been steamed and which may have been bypassed. Recently, radioactive tracer surveys have become more widely used to determine steam injection profiles. The surveying technique measures the transit time of a slug of a radioactive tracer between two downhole gamma radiation detectors. Preferably, inert radioactive gases, such as Argon, Krypton, or Xenon are used to trace the vapor phase and sodium iodide is used to trace the liquid phase. Methyl iodide has also been used to trace the vapor phase of the steam. For example, see U.S. Pat. Nos. 4,793,414; 4,817,713; 4,507,552, and an article by Davarzani and Roesner entitled "Surveying Steam Injection Wells Using Production Logging Instruments" dated Aug. 1985 and which describes U.S. Pat. No. 4,223,727.
In U.S. Pat. Nos. 4,507,552 and 4,223,727, radioactive Iodine is injected into the steam between the injection well and the steam generator. The tracer moves down the tubing with the steam until it reaches the formation, where the tracer is temporarily held on the face of the formation for several minutes. A typical gamma radiation log is then run immediately following the tracer injection. The recorded gamma radiation intensity at any point in the well is then assumed to be proportional to the amount of steam injected at that point.
Another prior art method to estimate injectivity into an injection well consists of measuring the volume of fluid and radioactive tracers injected with surface metering equipment, as described in U.S. Pat. No. 4,223,727.
The vapor phase tracers have variously been described as alkyl halides (methyl iodide, methyl bromide, and ethyl bromide) or elemental iodine. Although it has previously been believed that these alkyl halide vapor tracers were not subject to decomposition in the short time periods involved, it has been noted that the above materials undergo chemical reactions that dramatically affect the accuracy of the results of the survey in steam injection profiling as described in related U.S. Pat. Nos. 4,793,414 and 4,817,713.
A prior art method of determining relative liquid and vapor phase profiles in a steam injection well comprises the steps of inserting a well logging tool into the well at a first location, the tool comprising two gamma radiation detectors, one detector located a fixed distance above the second detector. A radioactive, liquid phase tracer is then injected, to determine a liquid transit time between the first and second gamma radiation detectors. A thermally stable, radioactive vapor phase tracer, such as Krypton, Xenon, or Argon gas, is then injected into the steam injection well and a vapor transit time between said first and said second gamma radiation detector is determined. The dual detector tool is then lowered to the next location and another slug of liquid or vapor phase tracer is injected.
The vapor or liquid injection profile in the perforated interval is then determined from the transit times at the different depths. For example, see U.S. Pat. Nos. 4,793,414 and 4,817,713.
An additional application has been proposed in which vapor and liquid velocities are used with measured bottomhole temperature or pressure and measured wellhead mass flow rate and vapor mass fraction of the two-phase steam to estimate the vapor mass fraction downhole. For examples, see U.S. Pat. Nos. 4,817,713 and 4,793,414. However, the accuracy of the estimated downhole vapor mass fraction primarily depends on the accuracy of the computed phase velocities.
Field experience with various prior art methods of steam profiling has shown considerable difficulty with repeatability and interpretation of results. Further evaluation of the practical application of radioactive tracer surveys to steam injection wells has shown that existing data analysis methods are not appropriate to determine short tracer transit times associated with steam injection wells. Because radiation particles are emitted randomly from background sources as well as from the tracer slug, it is important to distinguish tracer radiation decay events from background radiation levels. The current methods used by logging companies do not do this. As a result, detection of background radiation can often be falsely interpreted as detection of the tracer slug. In addition, it is important to avoid subjective interpretation of the detector response data. This means that automated data processing and evaluation are required. In general, automated methods are preferred over manual methods because they reduce analysis time, eliminate human error, and provide consistent and reliable results.
The signal transmitted by each detector is the occurrence of radiation decay events. The time of each decay event is recorded and stored for real-time and subsequent analysis. In the prior art, the signal from each detector is transformed to obtain a plot showing the number of recorded radiation decay events occurring within fixed time intervals. Ideally, this plot will exhibit a Gaussian distribution. Count rates are determined by counting the number of radiation decay events that occur within a fixed time interval. The arrival time of the tracer slug at the detector is identified as the time when the maximum or peak number of recorded decay events occurs or the time when the first significant increase in the number of decay events occurs. This method requires that very small time intervals be used to accurately identify tracer arrival times. For example U.S. Pat. No. 4,861,986 which issued Aug. 29, 1989, still teaches the method of selecting peaks to obtain measurements of the fluid flow velocity in leaks through a casing. Two radioactive isotopes are injected, which are theoretically distinguishable from one another.
In the application of radioactive tracers to steam injection profiling, a limited number of the total tracer decay events are detected. High vapor velocities associated with steam injection often create long tracer slugs of reduced concentration that pass by the detector quickly. Therefore, it can be difficult in these prior art methods to detect tracer decay events above background radiation levels. In addition, the high vapor velocities can result in very short tracer transit times between detectors. In some cases, transit times can be less than 0.2 seconds, making it difficult to evaluate and interpret tracer surveys using existing methods, as previously described.
Modifications to existing methods have recently been applied in attempt to account for the limited number of recorded decay events. The raw detector signal output is transformed into time intervals, .DELTA.t, between successive radiation decay events. The frequency, f, of the decay events at a given elapsed time are then obtained by using the inverse relationship, f=1/.DELTA.t. Exponential decline curves are used to fill in the gaps between discrete frequency values and additional smoothing techniques are used to obtain a continuous curve. Unfortunately, this final smoothed curve exhibits multiple peaks with widely varying shapes and does not represent the actual detector response. As a result, peak or leading-edge determination of the tracer arrival time becomes difficult, if not impossible.
An estimate of the accuracy of each frequency, determined from 1/.DELTA.t, can be obtained from EQU Accuracy of f=f+/-u.sub.f
where U.sub.f is the uncertainty of the frequency. If, for example, a 95% confidence level is used to define the uncertainty, then the accuracy of the frequency is given as EQU Accuracy of f=f+/-2.sigma.
where .sigma.is the standard deviation of the frequency. Since each frequency is based on a single value of .DELTA.t, its corresponding standard deviation is expressed as ##EQU1##
Therefore, the frequency of decay events obtained from values of 1/.DELTA.t are only accurate to within +/- two times itself. The true value of the decay event frequency falls somewhere within the range of -f to +3f, which indicates the large uncertainties associated with this method.
In the application of radioactive tracers to steam injection wells, a limited number of the total tracer decay events are detected. This results from the fact that the detector is exposed to the tracer for a very short time and that low levels of gamma radiation are used. Both exposure time and radiation level cannot be varied enough to significantly increase the number of detectable decay events. Increasing the time interval in which the decay events are counted decreases the accuracy of the estimated time that the count rates occur.
The existing methods are limited in the degree of accuracy attainable for determining the exact arrival time of a slug of radioactive tracer. High vapor velocities associated with steam injection can result in very short transit times between detectors. In some cases, transit times can be less than 0.2 seconds, making it difficult to evaluate and interpret tracer surveys. As a result, this limitation prevents an accurate determination of which portions of the reservoir are selectively receiving the injected steam. There is, therefore, still a need for a method of determining the arrival time at each detector, and the transit time between dual detectors, for a slug of radioactive tracer that is accurate, reliable, and practical to perform.